Azimuthally sensitive resistivity logging tool

ABSTRACT

Various systems and methods for implementing an azimuthally sensitive resistivity logging tool are disclosed. One such method involves transmitting a primary magnetic field from one or more coils placed on a drill collar and receiving several electrical signals, where each of the electrical signals is received from a respective one of several sensors. The sensors are distributed around a circumference of a drill collar, and an axis of at least one of the sensors is perpendicular to an axis of the drill collar. Each of the electrical signals indicates a respective magnitude of a measurement of a reflected magnetic field, where the reflected magnetic field is reflected from an anomalous geological formation. The method calculates a vector measurement of the reflected magnetic field, based upon the electrical signals.

FIELD OF THE INVENTION

This invention relates to the field of logging while drilling,particularly as used in oil and gas development and exploration.

DESCRIPTION OF THE RELATED ART

Logging is a technique that is used to measure one or morecharacteristics, such as resistivity, of subsurface geologic formations.Such a measurement can be used, for example, to determine the type ofsubsurface formation surrounding a drill bit. Accordingly, loggingprovides useful information to engineers and geologists engaged inhydrocarbon exploration and production as well as similar fields, suchas mining.

Logging can be performed by inducing a current to flow in a formationand then selectively measuring the current distribution. Severaldifferent techniques for performing logging have been developed. Forexample, open-hole logging involves in removing the drill pipe and bitfrom a wellbore and then lowering an open-hole logging tool into thewellbore to obtain the desired measurements.

Logging-while-drilling (LWD, also known as measurement-while-drilling(MWD)) systems have also been developed. These systems differ fromopen-hole logging in that measurements can be obtained while the drillpipe is in the wellbore. LWD systems permit log information, such asresistivity, to be measured in a formation very soon after the formationis penetrated by the drill bit. This provides substantially “real-time”information that (a) is obtained before the formation is substantiallyaltered by inflow of drilling fluids or other factors and (b) may beused by the driller to control the drilling operation, for example bysteering the bit so as to penetrate (or so as not to penetrate) aselected formation detected by the LWD system. LWD systems typicallyinclude transmitters and sensors disposed in or on sections of drillpipe that are located near the drill bit.

Some existing LWD systems have developed techniques to determine whetherthe drill bit is approaching an anomaly within a formation. However,these techniques generally lack the ability to pinpoint the location ofthe anomaly relative to the drill bit. Such techniques also lack theability to distinguish between a more conductive anomaly on one side ofthe drill bit and a less conductive anomaly on the other side of thedrill bit. In addition, existing techniques typically employ sensorsthat are responsive in only one rotational direction, requiring rotationof the entire drillstring to detect an anomaly, which may beinconvenient and time-consuming. Accordingly, improved techniques foruse in LWD systems are desirable.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present invention may be acquiredby referring to the following description and the accompanying drawings,in which like reference numbers indicate like features.

FIG. 1 illustrates a drilling system in which embodiments of the presentinvention can be employed.

FIGS. 2A-2C illustrate example sensor arrangements on alogging-while-drilling (LWD) tool, according to various embodiments ofthe present invention.

FIG. 3 is a cross-sectional view of the LWD tool, illustrating anexample sensor arrangement, according to one embodiment of the presentinvention.

FIG. 4 is a flowchart of a method of operating the LWD tool, accordingto one embodiment of the present invention.

FIG. 5 is a block diagram of components that can be included withinand/or coupled to the LWD tool, according to one embodiment of thepresent invention.

FIG. 6 illustrates the magnetic fields that can be induced and measuredby one embodiment of a LWD tool.

FIG. 7 illustrates how a vector representation of a reflected magneticfield can be calculated, according to one embodiment of the presentinvention.

FIG. 8A illustrates a view of a LWD tool showing how the receiver sensorcan be placed in the wall of the drill collar, according to oneembodiment of the present invention.

FIG. 8B illustrates another view of the LWD tool of FIG. 8A.

While the invention is susceptible to various modifications andalternative forms, specific embodiments of the invention are provided asexamples in the drawings and detailed description. It should beunderstood that the drawings and detailed description are not intendedto limit the invention to the particular form disclosed. Instead, theintention is to cover all modifications, equivalents and alternativesfalling within the spirit and scope of the invention as defined by theappended claims.

DETAILED DESCRIPTION

FIG. 1 illustrates how a drilling operation employs drilling rig 10 tocut a borehole 12 into the earth, penetrating the subsurface geologicalformation. Drillstring 16 passes through borehole 12 and is coupledbetween drilling rig 10 and a drill bit 14. Drillstring 16 includesdrill bit 14, drill collars 28, and drill pipe.

The lowest part of drillstring 16 is made up of drill collars 28. Drillcollars 28 are heavy walled pipe that provide weight on drill bit 14 andstrength to resist buckling under their own weight. The drill pipe isthinner walled. The drill pipe is kept in tension (which may be effectedby collars 28 placing weight on drill bit 14) to prevent buckling. Drillcollars 28 may have radial projections (not shown) called stabilizers.Short drill collars, which may be adapted for specialized functions, arecalled “subs,” and references herein to drill collars are intended toinclude subs.

Drilling rig 10 turns drill bit 14, which cuts through the rock at thebottom of borehole 12. In some situations, drilling rig 10 turns drillbit 14 by attaching drill bit 14 to the lower end of drillstring 16 andturning drillstring 16 with powered equipment at the surface.Alternatively, as shown in FIG. 1, drill bit 14 may be driven by a motor18, which is adjacent to drill bit 14 in borehole 12, through bent sub20. The illustrated arrangement is known as a “steering tool” system, inwhich drillstring 16 does not need to rotate to turn the drill bit.However, drillstring 16 can be turned to steer drill bit 14, so as tocontrol the direction of advance of borehole 12, thus permitting theroute of borehole 12 to be precisely steered as desired through thesubsurface geologic formation.

A logging-while-drilling (LWD) tool 22 is placed in drillstring 16, neardrill bit 14 (if LWD tool 22 is used for geosteering, it may bedesirable to locate LWD tool 22 as close as possible to drill bit 14).In a steered system, the LWD tool may be placed above mud motor 18, suchthat LWD tool 22 receives power and returns data to the surface througha wire line cable 24 that is passed down the center of a non-rotating(or slowly rotating) drillstring 16. In a system that uses a rotatingdrillstring 16 to turn drill bit 14, LWD tool 22 may be placed justabove drill bit 14, and a mud pulse data telemetry system (or any otherappropriate telemetry method) can be used to return information to thesurface. Thus, LWD tool 22 is operatively positioned in borehole 12,typically with an annular space (e.g., filled with drilling mud) betweentool 22 and the borehole wall.

LWD tool 22 can incorporate or be associated with directional sensors 26that provide directional information to the driller to assist incontrolling the steering of the drill bit. For example, such directionalsensors can be calibrated to indicate the position of the LWD tool 22relative to an absolute direction, such as the gravity vector ormagnetic north.

LWD tool 22 also includes several receiving sensors, such as coils, thatare each configured to measure a reflected magnetic field, as well asone or more transmitter coils that are configured to generate a magneticfield. In operation, LWD tool 22 generates a magnetic field, which isoutput by one or more transmitter coils. This magnetic field passesthrough the surrounding subsurface geologic formation and, if ananomalous formation is present, is reflected by that anomalousformation. The reflected magnetic field, if any, is detected by each ofthe receiving sensors included within LWD tool 22 (these sensors can, inat least some configurations, also detect the primary magnetic fieldinduced by the transmitter coils). Since each sensor is located at aslightly different location, each sensor may detect a differentmagnitude of the magnetic field.

The portion of the magnetic field that is received by each sensor issensed and quantified by electronics within LWD tool 22. The magnitudeof the detected magnetic field has an inverse relationship to theformation's resistivity in proximity to the receiving sensor. Thus, thequantified detected magnetic field can be converted to information thatidentifies the resistivity (or conductivity, which is simply the inverseof resistivity) of the proximate portion of the formation. Additionally,differences between the quantified reflected magnetic field, as seen ateach of the different sensors, can be used to determine the azimuthaldirection, relative to the position of the drill collar, to an anomalousformation. LWD tool 22 can also include or be coupled to telemetry orother communication equipment to transmit this information to theearth's surface.

Above the earth's surface 30, telemetry receivers and/or otherappropriate communication equipment can be located in a logging truck 32located near drilling rig 10. Thus, communication equipment ispositioned to receive and interpret the information generated by LWDtool 22 and directional sensors 26, so that the information can becollected for later analysis and/or used to steer wellbore 12 into thedesired position (e.g., to maximize recovery of hydrocarbons from aselected reservoir).

A data display panel 34 can be provided on or near drilling rig 10and/or logging truck to give an operator (e.g., a driller, engineer,geologist, or the like) real-time information about the directionalprogress of wellbore 12 as well as the formation properties of thegeologic formation currently near LWD tool 22. In one embodiment, datadisplay panel 34 can be part of a computing device (e.g., data displaypanel 34 can be rendered on the screen of a laptop computer used by anoperator of drilling rig 10). Data display panel 34 can provide a polardisplay indicating formation properties of an anomaly within thegeologic formation. For example, information identifying (or usable toidentify) the resistivity (or another electrical characteristic) of suchan anomaly can be provided by LWD tool 22. This information can beprocessed in order to render a polar display (or other graphical userinterface) showing the orientation of and/or distance to the anomalousformation from the borehole (e.g., by showing the borehole in the centerof a polar display and rendering a visual representation of the locationof the anomalous formation relative to the borehole).

FIGS. 2A-2C illustrate example sensor arrangements for LWD tool 22. Ineach example, there are several transmitting coils, which can be used toinduce a magnetic field in the surrounding formation, and severalreceiving sensors, which can each detect the induced magnetic fieldand/or a reflected magnetic field. Many other sensor configurations arepossible in addition to those shown herein.

LWD tool 22 can be implemented as a sub (e.g., a drill collar) for useas part of a drillstring, as described above. In one embodiment, thestructural features and physical components of LWD tool 22 are similarto those described in U.S. Pat. No. 6,064,210, which issued on May 16,2000 and names Paul L. Sinclair as inventor, and which is herebyincorporated by reference as if completely and fully set forth herein.

The transmitter coils described herein are induction tools (e.g.,inductors) that create an alternating magnetic field that propagatesaround and/or away from LWD tool 22. In some embodiment, suchtransmitter coils operate at a frequency in the range of 200 Kilohertz(KHz) to 2 Megahertz (MHz). A given embodiment may employ one or moretransmitter coils configured to operate at a single frequency ormultiple frequencies within this range.

In some embodiments, LWD tool 22 enables the transmitter coil byproviding a sinusoidal current at a chosen frequency (e.g., within therange mentioned above) to the transmitter coil, which in turn causes thetransmitter coil to generate the magnetic field. In many embodimentsthat employ multiple transmitter coils, the transmitter coils areoperated in an interdependent manner (as opposed to being operatedindependently, where each transmitter coil receives an independentlygenerated sinusoidal current, which may be done in alternativeembodiments). Thus, the same sinusoidal current can be provided to morethan one transmitter coil in at least some such embodiments.

The receiving sensors described herein can be implemented using anysensor that is capable of detecting the magnitude and/or phase of amagnetic field. In one embodiment, the receiving sensors are coils(e.g., inductors) made of insulated copper wire. Ferromagnetic materialcan be placed inside each coil (e.g., to provide enhanced effectivecross-section area). In alternative embodiments, the receiving sensorsare Hall-effect sensors. Other types of appropriate sensors may also beused.

FIG. 2A illustrates an axial view of a LWD tool having a sensorarrangement that includes four transmitter coils and two sets ofreceiving sensors, each containing four sensors. As shown, LWD tool 22is implemented as a drill collar that includes a drilling mad channel102 along the long axis of LWD tool 22 to allow drilling mud (a drillingfluid) to flow to the drill bit.

Four transmitter coils 104 are distributed around the circumference ofthe LWD tool, at a position that is closer to one end (shown towards theleft hand side of FIG. 2C) of LWD tool 22. Due to the orientation of LWDtool 22 in this example, only three of the transmitter coils arevisible. These transmitter coils 104 are located within the same plane,which forms a transverse (perpendicular to the long axis of LWD tool 22)cross section of LWD tool 22. Transmitter coils 104 are positioned suchthat the long axis of each transmitter coil is parallel to the long axisof LWD tool 22.

In this example, these transmitter coils are located within recesses 106in the body of LWD tool 22. These recesses can be machined into the bodyof LWD tool 22. The recesses can be filled with non-conductive material.The transmitter coils can be insulated from each other, as well as fromthe receiver sensors.

Two sets of receiver sensors are distributed around the circumference ofthe other end (away from the transmitter coils) of LWD tool 22. Thereceiver sensors are configured to detect the magnetic field induced bythe transmitter coils. Since the receiver sensors are detecting amagnetic field, there is no need for a physical electrical connection tocouple the transmitter coils and receiver sensors.

In one embodiment, the receiver sensors are located approximately 2meters from the transmitter coils. Each set of receiver sensors islocated in a respective plane, each of which forms a transverse crosssection of LWD tool 22. Receiver sensors 108 include four sensors (onlythree of which can be seen in the view of FIG. 2A) that are orientedsuch that their axis is parallel to the long axis of LWD tool 22 and thelong axis of each of the transmitter coils. Receiver sensors 108 arelocated within recesses 110 in the body of LWD tool 22. Like therecesses that house the transmitter coils, recesses 110 can be filledwith non-conductive material.

The second set of receiver sensors, receiver sensors 112, is alsodistributed around the circumference of LWD tool 22. Receiver sensors112 are placed in a different transverse cross sectional plane of LWDtool 22 than receiver sensors 108. Receiver sensors 112 are orientedsuch that a long axis of each of receiver sensors 112 is perpendicularto the long axis of LWD tool 22, as well as to the long axis of each ofreceiver sensors 108 and the long axis of each of the transmitter coils104. Receiver sensors 112 are located within recesses 114 in the body ofLWD tool 22. Like the recesses that house the transmitter coils andreceiver sensors 108, recesses 114 can be filled with non-conductivematerial.

Each of receiver sensors 108 and 112 is configured to operateindependently. Accordingly, each receiver sensor can independentlymeasure a magnetic field, such that each receiver sensor obtains adifferent measurement of the same magnetic field. Thus, the receiversensors 108 and 112 can each be insulated from each other, as well asfrom transmitter coils 104.

Receiver sensors 108 and 112 are each configured to output an electricalsignal indicative of the magnitude and/or phase of a detected magneticfield. In one embodiment, each of receiver sensors 108 and 112 is areceiver coil. The magnetic field induces a voltage in these coils. Themagnitude and phase of this induced voltage in the receiver coils,relative to the current (which is used to enable the transmitter coilsto generate the magnetic field) in transmitter coils 104, provides ameasure of the electrical resistivity of the surrounding formation. Thephase difference and/or amplitude ratio of the induced voltages in (orresistivity measured at) a pair of the receiver sensors can be used todetermine the resistivity of the portion of the formation that liesbetween the two receiver sensors in the pair.

The orientation of each receiver sensor's long axis, relative to theorientation of the transmitter coil(s), determines the portion of themagnetic field that the receiver sensor will be sensitive to, as will beexplained in the context of FIG. 6. FIG. 6 illustrates an LWD tool 22that is moving through a formation 404. An anomalous formation 406 islocated at a distance from the LWD tool 22. LWD tool 22 induces aprimary magnetic field 400 (for simplicity, only a representation of themagnetic component of this field is included) in the surroundingformation. Primary magnetic field 400 propagates in all directions withaxial symmetry. The primary magnetic field is affected by surroundingformation 404, and thus the measurement of the primary magnetic fielddetected by the receiving sensors indicates the resistivity of thesurrounding formation 404.

Since primary magnetic field 400 is an alternating field whichpropagates through the rock media, it is partially reflected by theboundary between media of differing resistivities. Accordingly, theprimary magnetic field is reflected by the anomalous formation 406. Theresulting reflected field 402 alters primary magnetic field 400, tiltingthe angle of the primary magnetic field's vector by an amount that isrelated to the relative strength of the reflection and the distance tothe boundary between surrounding formation 404 and anomalous formation406. The effect of the reflected magnetic field on the primary magneticfield is more pronounced closer to the boundary between the twoformations, such that a receiver sensor closer to the boundary willrespond to a stronger component of the reflected magnetic field than areceiver sensor further from the boundary.

The receiver sensors that are oriented in the same manner as thetransmitter coils will be primarily sensitive to the primary magneticfield. These receiver sensors will also be sensitive to the reflectedmagnetic field. In particular, these receiver sensors (e.g., receiversensors 108 of FIG. 2A) will detect the reflected magnetic field via itseffect on the primary magnetic field.

The receiver sensors (e.g., receiver sensors 112 of FIG. 2A) that areoriented with their long axes perpendicular to the orientation of thetransmitter coils are orthogonal to the primary magnetic field.Accordingly, these sensors will not respond to the primary magneticfield. However, these sensors will be sensitive to the reflectedmagnetic field. Accordingly, embodiments that include these sensors canprovide an increased sensitivity to the reflected magnetic field,relative to the sensors that are configured to respond primarily to theprimary magnetic field.

As LWD tool 22 moves through the borehole, LWD tool 22 can detectchanges in the resistivity of the surrounding formation. Such changes inresistivity indicate that the surrounding formation is changing, sincedifferent types of geological formations have different resistivities.Thus, the presence of an anomalous formation within the surroundingformation will cause the detected resistivity to change as the drill bitnears the anomalous formation. The measured resistivity can be used todetermine the type of geological formation surrounding the drill bit, aswell as the type and/or location of anomalies within the surroundinggeological formation, as will be discussed in more detail below.

FIG. 2B shows an alternative sensor arrangement. In this example, LWDtool 22 includes four sensors 108 that are oriented such that the longaxis of each sensor 108 is parallel to the long axis of LWD tool 22 andeach of the transmitter coils 106. Receiver sensors 108 are sensitive toboth the primary and reflected (if any) magnetic fields.

FIG. 2C shows yet another alternative sensor arrangement. In thisexample, LWD tool 22 includes four sensors 108 that are oriented suchthat the long axis of each sensor 108 is perpendicular to the long axisof LWD tool 22 and each of the transmitter coils 106. In this example,the receiver sensors 108 are sensitive to the reflected magnetic field(if any) but not to the primary magnetic field.

The sensor arrangements of FIGS. 2A-2C allow each set of sensors 108and/or 112 on LWD tool 22 to simultaneously obtain measurements of therelative magnitude and/or phase of a magnetic field at four distinctpoints that are evenly distributed around the circumference of the drillcollar. Accordingly, the magnitude and/or phase of the magnetic fieldsurrounding LWD tool 22 can be sensed in each of four directionssimultaneously. This allows an operator (i.e., a person controlling thesteering of a drill bit to which LWD tool 22 is coupled) to use LWD tool22 to determine the location of anomalous formations, if any, that thedrill bit may be approaching in any of those four directions, withoutrotating LWD tool 22. Reducing the need to rotate the LWD tool 22 cansimplify and/or speed up the operation of LWD tool 22.

As noted above, many other sensor configurations are possible, inaddition to those shown in FIGS. 2A-2C. For example, one alternativeembodiment may employ only two receiver sensors (or two sets, eachhaving two receiver sensors, where the axis of the sensors in one set isperpendicular to the axis of the sensors in the other set). When in use,an operator may rotate the LWD tool 180 degrees in between two sets ofmeasurements at a given location, in order to obtain the samemeasurements that could be obtained simultaneously if four receivingsensors were used.

Other numbers of receiver sensors can also be included within each set,so long as each set includes at least two sensors. For example, someembodiments may include three sensors, while other embodiments includeeight sensors.

As another example, instead of having each sensor within a given set ofsensors (where each set contains sensors having substantially the sameaxis orientation, relative to the axis of the drill collar) insubstantially the same cross-sectional plane of the drill collar, somesensors in a given set are located in a different cross-sectional planethan other sensors in the same set. Similarly, in some alternativeembodiments, sensors from different sets may be arranged insubstantially the same cross-sectional plane of the drill collar.

Another variation in sensor configuration can switch the location of thetransmitter coils and one or both sets of receiver coils. Thus, someembodiments may place transmitter coils closer to the drill bit andreceiver sensors towards the other end (furthest from the drill bit),while other embodiments place one or both sets of receiver sensorscloser to the drill bit while placing the transmitter coils further fromthe drill bit. Similarly, in one embodiment, the transmitter coils maybe located towards the middle of the drill collar, and one or more setsof receiver sensors may be located towards each end of the drill collar,such that the transmitter coils are between two sets of receiversensors. Still another variation in sensor arrangement can orient thetransmitter coils such that the long axis of the transmitter coils isperpendicular to the long axis of the LWD tool.

FIG. 3 illustrates a cross-sectional view of LWD tool 22. This viewshows the drilling mud channel 102 passing through the middle of LWDtool 22. Four recesses, 110(a), 110(b), 110(c), and 110(d), extend intothe body of LWD tool 22. These recesses are all located in the samecross-sectional plane. These recesses are spaced 90 degrees apart fromeach other around the circumference of LWD tool 22.

A receiver sensor (e.g., one of receiver sensors 108 of FIGS. 2A and 2C)has been inserted into each recess. In particular, receiver sensor108(a) is located within recess 110(a), receiver sensor 108(b) islocated within recess 110(b), receiver sensor 108(c) is located withinrecess 110(c), and receiver sensor 108(d) is located within recess110(d). The receiver sensors are oriented such that the axis of eachsensor is parallel to the axis of LWD tool 22.

A similar spacing and arrangement (now shown in FIG. 3) of sensors canbe used to hold sensors (e.g., such as sensors 112 of FIGS. 2A and 2C)that are oriented such that the axis of each sensor is perpendicular tothe axis of LWD tool 22. Thus, appropriate recesses to hold sensorsoriented in that manner can be located in the same cross-sectionalplane, spaced 90 degrees apart from each other.

Different embodiments can vary from the spacing described herein. Forexample, due to imprecision in measurement and/or machining tools, it isoften impractical to attempt to obtain perfectly even spacing.Accordingly, most embodiments allow for some margin of error (e.g.,0.5%, 1%, or 5%, depending on the measurement and/or machining toolsavailable and/or the desired accuracy of the resulting LWD tool) in thespacing and/or orientation of the transmitting coils and/or receiversensors.

In some embodiments, even greater variations in spacing are used.Instead of having each sensor be arranged at a position that is spacedapproximately 90 degrees from two other sensors, alternative embodimentsmay locate sensors around the circumference of the drill collar using amore varied spacing. For example, in one alternative embodiment, eachsensor may be located closer than 90 degrees (e.g., 80 degrees) to oneneighboring sensor and more than 90 degrees (e.g., 100 degrees) from theother neighboring sensor.

The position of each sensor can be mechanically keyed to a separatedirectional sensor or orientation sensor (e.g., a gyroscope). Thisallows the signal detected by each sensor to be analyzed as a componentof a vector electromagnetic field, which has a direction referenced tothe gravity vector and/or the direction of the magnetic north pole, orto an inertial reference vector.

FIG. 4 is a flowchart of a method of using a LWD tool that has a sensorarrangement like one of those described above, in which more than onereceiver sensor independently obtains a measurement of a magnetic field.This method can be performed by a LWD tool 22 as described in thefigures above, in combination with components such as those shown inFIG. 5 (if such components are not integrated into LWD tool 22).

The method begins at 200, when a magnetic field is induced in aformation. As noted above, inducing a magnetic field can involveapplying a sinusoidal current to one or more transmitter coils at aprespecified frequency. This operation can be performed by a currentgenerator (e.g., an oscillator operating under the control of a controlmodule, which can in turn be responsive to an operator's commands totake a measurement), operating in conjunction with one or moretransmitter coils that are coupled to receive the sinusoidal currentproduced by the current generator.

At 205, electrical signals (e.g., a voltage induced in two or morereceiver sensors) are received. The electrical signals indicate themagnitude and/or phase of a reflected magnetic field at multiplelocations around the drill collar. In particular, each electrical signalindicates the magnitude and/or phase of a reflected magnetic field, asmeasured at a respective one of several locations along thecircumference of the drill collar. These electrical signals aregenerated by two or more receiver sensors and received by componentssuch as those shown in FIG. 5. As noted above, the magnitude and/orphase of the reflected magnetic field can be detected by measuring thereflected magnetic field directly (e.g., through the use of sensors thatare oriented with their axes perpendicular to the orientation of thetransmitter coil(s)' axes) or indirectly (e.g., through the use ofsensors that are oriented with their axes parallel to the orientation ofthe transmitter coil(s)' axes, where such sensors measure the reflectedmagnetic field based upon its effect on the primary magnetic field).

At 210, a vector representation of the reflected magnetic field iscalculated, based upon the electrical signals received at 205. Thisvector representation can be calculated by a control module (e.g.,control module 302 of FIG. 5 below), which can be included within and/orcoupled to the LWD tool. This vector representation can then bedisplayed to an operator, logged, and/or used to generate a moresophisticated display (e.g., such as a polar display for geosteeringapplications). More details regarding the calculation of this vectorrepresentation are provided below. The vector representation indicatesthe location of (e.g., in terms of an azimuthal angle), distance to, andresistivity of the anomaly. The latter two components of the vectorrepresentative can be relative, such that the vector can representmultiple possibilities, including a less resistive anomaly closer to theLWD tool and a more resistive anomaly further from the LWD tool.Historical data about a formation can be used to select a more specificinterpretation of the vector.

FIG. 5 is a block diagram of circuitry 300 that can be included withinand/or coupled to LWD tool 22. Circuitry 300 includes a control module302, a power amplifier 304, one or more low-noise amplifiers 306 (onlyone such low-noise amplifier is illustrated in FIG. 5; however, one suchamplifier can be included for each receiver sensor), a switching module308, a switching module 312, an oscillator 310, signal mixer, detector,and filter 314, analog-to-digital converter 316, and transmission module318. Circuitry 300 can also include one or more memory devices such asmemory 320.

Oscillator 310, switching module 310, and power amplifier 304 operate toenable one or more transmitter coils in order to induce a magnetic fieldin a formation surrounding the LWD tool. In particular, oscillator 310(or any other appropriate current generator) generates a sinusoidalcurrent (e.g., in the range of 100-400 KHz), which is then provided topower amplifier 304 via switching module 312. In this embodiment,control module 302 controls switching module 312 in order to select whenthe sinusoidal current is provided to power amplifier 304 (e.g., thecurrent can only be provided when an operator is requesting that themagnetic field be induced in the surrounding formation for testingpurposes). Power amplifier 304 amplifies the sinusoidal current, whichis then provided to one or more transmitter coils (not shown) in the LWDtool.

The frequency of oscillator 310 can be selected based upon the desiredresponsiveness of the LWD tool. For example, in many situations, it isdesirable to maximize the distance from the borehole at which the LWDtool is able to sense an anomalous formation, since this will give adriller early warning that he may soon encounter changed formationconditions. The radial depth of investigation is strongly influenced bythe phenomenon of “skin depth,” which is a characteristic distance thatan alternating magnetic field can penetrate into a conductive medium.The skin depth is defined as the distance at which an electromagneticfield has experienced a phase-shift of 45 degrees and an attenuation of1/e (−8.68 dB). Skin depth may be calculated as follows:

Skin Depth, δ(meters)=(2/ω·μ·σ)^(1/2)  (Eq. 1)

where ω is the angular frequency (radians/second), μ is the magneticpermeability of the medium (Henries/meter), and σ is the conductivity ofthe medium (Siemens/meter).

Since the field must penetrate into the formation and be reflected backto be detected by the receiving sensors, the field effectively makes twotrips, so the attenuation and phase-shift of the received signal will bedoubled when the investigation distance equals the skin-depth. Apractical limit for detection distance is when the attenuation reducessignal levels below the noise or accuracy limit of the measurementcircuits attached to the receiving coils. To maximize the skin-depth ina given medium, one can choose to minimize the frequency since this isthe only independent parameter. However, the magnitude of the signalinduced in a receiving sensor is proportional to frequency, so a bestcompromise must be found in the tool design. Such a compromise can befound by using a frequency in the range of 100-400 KHz for embodimentsin which the transmitter coils are spaced a few meters or so from thereceiver sensors. At a frequency of 200 KHz, the skin depth ranges from0.4 to 40 meters for a typical rock resistivity range of 0.1 to 1000ohm-meters. Thus, the potential depth of investigation could be at leastseveral meters in the higher resistivity range typical of mosthydrocarbon-bearing reservoir rocks.

A voltage, which is dependent upon the magnetic field in the surroundingformation, can be induced in each receiver sensor. Each of the receiversensors (not shown) is coupled to a respective low noise amplifier 306,which amplifies the signal induced in the respective receiver sensor andprovides that amplified signal to switching module 308. Control module302 controls switching module 308 (e.g., in order to select whichreceiver sensor's output is input to signal mixer, detector, and filter314 at any given time).

The output of switching module 308 is provided to signal mixer,detector, and filter 314. Signal mixer, detector, and filter 314 alsoreceive a reference signal (f_(ref)) (e.g., indicating the signalprovided to the transmitter coils) from oscillator 310. Signal mixer,detector, and filter 314 can, among other things, remove unwanted noisefrom the amplified signal. For example, signal mixer, detector, andfilter 314 can remove unwanted noise from image frequencies.

Signal mixer, detector, and filter 314 provides its output toanalog-to-digital converter 316, which in turn outputs a digitalrepresentation of the signal received from signal mixer, detector, andfilter 314 to control module 302. Control module 302 then processes thisdigital signal (in conjunction with other digital signals representingthe signals detected at the other sensors included in the LWD tool) inorder to produce a vector representation of the reflected magneticfield. In particular, control module 302 can obtain the magnitude and/orphase of the signal detected at each sensor, as well as positionalinformation identifying the location of each sensor (e.g., relative tothe gravity vector, magnetic North, or the axis of the LWD tool), inorder to obtain a vector representation of the magnetic field. Thisvector representation can then be used to determine the resistivity andlocation (e.g., in terms of direction and distance) of an anomalousformation. Control module 302 can also process the received digitalsignals in order to identify the resistivity of the surroundingformation in the absence of any anomaly.

In one embodiment, the magnitude and phase of the induced voltage in apair of receiver sensors (a pair includes two sensors in the same set,which includes sensors having the same orientation, that are spacedapproximately 180 degrees apart from each other on the circumference ofthe LWD tool), relative to the current in the transmitter coil, is anaccurate measure of the electrical resistivity of the rock in a selectedlocation. Accordingly, the phase difference or the amplitude ratiobetween signals from a pair of closely-spaced receiver sensors (e.g.,any two of the receiver sensors in a given set of similarly orientedreceiver sensors) provides an accurate indication of rock resistivity ina narrow slice of rock between the sensors. Thus, control module 302 cancalculate a value that is representative of the formation resistivity,based upon the signals received from the receiver sensors.

In particular, for a pair of sensors having axes parallel to the axis ofthe transmitter coil(s), the vector representation of the magnetic fieldcan be calculated by calculating the ratio of the signals obtained bythat pair of sensors. This representation also indicates the resistivityof the formation generally located in the axial region between thesensors. The signals received by these sensors, which are responsive toboth the primary and reflected (if any) magnetic fields, can be used tocalculate the resistivity of both a homogeneous geological formation andan anomalous geological formation (if any).

If instead the pair of sensors have axes that are perpendicular to theaxis of the transmitter coil(s), so that the sensors are only sensitiveto a reflected magnetic field, if any, the signals from these sensorscan be used to determine the resistivity of an anomalous formation(e.g., by calculating the ratios of signals received by pairs ofsensors).

If two sets of sensors, which are oriented perpendicular to each other,are included, the signals received from one set of sensors (e.g., thosesensors sensitive to the primary field) can be used to calculate theresistivity of a homogeneous surrounding geological, while the signalsreceived from the other set of sensors can be used to calculate theresistivity of the anomalous geological formation.

In general, when a receiver sensor is spaced apart from a transmittercoil, the voltage V induced in a receiving sensor due to a sinusoidalcurrent I flowing in the transmitter coil is:

V(volts)=−jωM·(1−jkL)·e ^(jkL) ·I(amperes)  (Eq. 2)

where j is the imaginary operator (−1)^(1/2), M is the mutual inductancebetween the transmitter and receiver (Henries), L is the spacing betweenthe transmitter and receiver (meters), k is the complex propagationcoefficient of the medium, k=[jωμ(σ+jω∈)]^(1/2), and ∈ is the dielectricpermittivity of the medium (Farads/meter).

Assuming that the dielectric permittivity of the medium has negligibleeffect on propagation, then the propagation coefficient reduces to theform:

k=(jωμσ)^(1/2)  (Eq. 3)

k=(1+j)/δ  (Eq. 4)

Substituting this into Eq. 2 and re-arranging terms results in thesimplified form:

V/I=−jωM·[1−(j−1)L/δ]·e ^((j−1)L/δ)  (Eq. 5)

In Eq. 5, V/I represents a transfer-function between coils, jωMrepresents the low-frequency mutual coupling, [1−(j−1)L/δ] representsthe spreading effect (since this example is focused on operating in thenear-field region of the transmitter and receivers), and e^((j−1)L/δ)represents the plane-wave propagation in the medium. L/δ is adimensionless term, since it is a ratio between two physical distances.

Control module 302 can be configured to use Eq. 5 to predict thephase-shift and attenuation of the transfer-function in a medium ofvarying conductivity. Circuitry 300 can be configured to also use Eq. 5to predict the reflected field from a rock-bed boundary (e.g., theboundary between a surrounding formation and an anomalous formation) inproximity to the LWD tool. If the boundary is parallel to the tool axisand at a distance of D meters, then the total distance from transmittercoil to the boundary and back to the receiver sensor is a matter ofgeometry:

Total Distance D′=2[D ²+(L/2)²]^(1/2)  (Eq. 6)

Substituting D′ for L in Eq. 5 allows calculation of the reflectedcomponent of the signal, assuming that the reflection coefficient of theboundary is nearly −1, which is true if there is a large ratio (>10)between the conductivities of the two media on either side of theboundary. If we are only concerned with the phase of a received signalrelative to the phase of the induced primary magnetic field, then thephase velocity of the field is constant in the medium regardless ofdistance, so the phase-shift may be simply represented as:

Phase-shift Θ=πD′/4δ  (Eq. 7)

If the receiver sensor is oriented in a manner (e.g., such as shown inFIG. 2C) that is only responsive to a reflected signal from a boundary(i.e., and not to a signal in which the reflected signal is added to adirect signal, as shown in FIG. 2B) then it is easy to invert thisequation to determine distance from the phase measured by that receiversensor:

Distance to Boundary D=[(2Θδ/π)²−(L/2)²]^(1/2)  (Eq. 8)

The resistivity of the rock surrounding the tool can be determined fromthe simultaneous measurement with receiver sensors that are oriented inthe same manner as the transmitter coils (e.g., as shown in FIG. 2B).For example, if all of those receiver sensors detect approximately thesame resistivity value, then that value indicates the resistivity of thesurrounding formation. If the sensors begin to detect different values,the most recent consistent (among those sensors) value can be used asthe resistivity of the surrounding formation, and the difference amongsensor outputs can be attributed to an anomalous formation that the LWDtool is approaching. A value indicating the resistivity of thesurrounding formation (or a log of such values, and the time (and/orlocation) at which each value was obtained) can be stored in memory 320.

Control module 302 can use that resistivity of the surrounding formationto compute the skin-depth to be used in Eq. 8, and hence find the valueof D. In some embodiments, an advanced 3-dimensional Finite-Elementcomputer-modeling program such as FEMLAB™, available from Comsol, Inc.of Burlington, Mass., may be employed to simulate a wide range offormation conditions and to create a database, allowing control module302 to perform inversion of measured phase-shift to actual boundarydistance using the measured phase-shift and the database of simulatedformation conditions. Such simulated results can be stored in memory 320(e.g., in the form of a lookup table), allowing control module 302 tolookup a measured phase shift and obtain an appropriate distance to aboundary.

Thus, control module 302 can detect whether the LWD tool (and thus thedrill bit to which the LWD tool is attached) is approaching or movingaway from an anomaly. For example, as described above, control module302 can compare the most recently calculated set of apparentresistivities detected by each sensor to historical resistivity values(e.g., generated by a computer-modeling program) stored in memory 320.If any of the resistivities have increased relative to the historicalresistivities, control module 302 can determine that the LWD tool isapproaching a more resistive anomaly. Similarly, if any of the detectedresistivities have decreased relative to the historical resistivities,control module 302 can determine that the LWD tool is approaching a lessresistive anomaly.

The output from a directional sensor included in and/or coupled to theLWD tool can then be used to determine the relationship between thatknown point and a standard directional vector, such as magnetic north orthe gravity vector. The output from the directional sensor can thus beprovided to control module 302, which can use this information tocalculate a relative azimuthal angle describing the location of theanomaly relative to the standard directional vector.

More exact techniques can be used to calculate the azimuthal angle anddistance to a resistivity anomaly using the configuration of thesensors. An example is described below with respect to FIG. 7.

FIG. 7 illustrates a vector representation of a reflected magnetic field(produced by, for example, a resistivity anomaly such as a rock-bedboundary between two rocks of contrasting resistivity) relative to a LWDtool 22. As shown, the LWD tool 22 includes a pair of sensors, labeled Xand Z. Sensor X has a long axis that is perpendicular to the axis 700 ofLWD tool 22 and a transmitter coil. Sensor Z has a long axis that isparallel to axis 700 of LWD tool 22 and the transmitter coil.

The magnetic field vector (shown as a bold arrow pointing towards LWDtool 22) approaches LWD tool at a relative angle θ that is defined withrespect to axis 700 of LWD tool 22. The magnetic field vector is normalto the surfaces of constant magnetic field strength, and indicates thegeneral direction of a resistivity anomaly such as a bed-boundary thatattenuates and reflects a magnetic field generated by a transmitterwithin LWD tool 22.

A voltage is induced in each of sensors X and Z by the magnetic field.The voltage induced in sensor X is V_(x) and the voltage induced insensor Z is V_(z). These voltages can be used to calculate the relativeangle θ as the arctangent of the ratio of V_(x) to V_(z), such thatθ=arctangent (V_(x)/V_(z)). This angle represents the relative angle inthe plane defined by the X and Z axis. This technique allows therelative angle to be detected, while also providing a robust LWD toolassembly since very little metal needs to be removed from thecircumference of the collar to allow for insertion of the sensors.

If there is a similarly oriented sensor Y (not shown in FIG. 7), located90° away from sensor X along the circumference of LWD tool 22 and havingits long axis perpendicular to the Z sensor axis (and thus beingoriented similar to sensor X), a second angle Φ can be calculated as thearctangent of the ratio of the voltage V_(y) induced in sensor Y toV_(z), such that Φ=arctangent (V_(y)/V_(z)). This angle represents therelative angle of the vector in a plane defined by the Y and Z axis.

The two angles together specify the direction of the magnetic fieldvector relative to axis 700 of LWD tool 22. In some embodiments,additional calculations can be applied to the calculated angles and/orduring the calculation of these angles. For example, the voltagesinduced in the sensors can be scaled to account for differences in thegain of each of the sensors, and also to correct for the influence ofthe conductive drill collar of LWD tool 22, which can perturb themagnetic field detected by all or some of the sensors. The correctionscan be derived from computer modeling of the performance of LWD tool 22in various situations.

The two angles can be combined with the distance estimate describedabove to provide a complete vector representation, in terms of distance,magnitude, and angle, of the magnetic field. The magnitude V_(m) of themagnetic field is equal to the square root of the sum of V_(x) squared,V_(y) squared, and V_(z) squared. Again, certain scaling factors can beapplied to the component voltages prior to calculating V_(m), dependingupon the particular configuration of the sensor coils being used.

Another more general solution of the measured voltages V_(x), V_(y) andV_(z) in a polar coordinate system is more useful in some situations. Wedefine an azimuthal angle (here, an angle of rotation around the Z axisrelative to a fixed reference-point) as AZI, and an angle relative tothe Z axis in any azimuthal direction (i.e., a relative bearing) as RB.Then AZI=arctangent (V_(y)/V_(x)) and RB=arccosine (V_(z)/V_(m)). Withthis solution, it is not necessary to rotate the drill-collar to obtaina complete solution of the direction of the magnetic vector.

Using the AZI angle and the Distance D as described previously, the datapresentation method described in copending U.S. patent application Ser.No. 11/756,504, titled “Azimuthal Measurement While Drilling (MWD)Tool,” filed May 31, 2007, and naming Paul L. Sinclair and Thomas A.Springer as inventors, can be used to generate a polar display. Thisapplication is hereby incorporated by reference as if completely andfully set forth herein.

Returning to FIG. 5, transmission module 318 is configured tocommunicate information received and/or calculated by control module 302to another sub or to a surface system. For example, transmission module318 can receive information generated by control module 302 (e.g., byreceiving the information directly from control module 302 or byretrieving such information from a storage device such as memory 320)that indicates the resistivity of the surrounding formation and transmitthis information to a surface system. Alternatively, transmission module318 can transmit information indicative of the magnitude and/or phase ofthe reflected electromagnetic field detected at each sensor to a surfacesystem, allowing the surface system to calculate the resistivity of thesurrounding formation from the data collected by LWD tool 22.

Transmission module 318 can also receive information sent to controlmodule 302 by a surface system and/or another sub. For example,transmission module 318 can receive information indicating that asurface user would like LWD tool 22 to begin measuring the resistivityof the surrounding formation. Transmission module 318 can provide thisinformation to control module 302 and/or store this information forsubsequent access by control module 302. Transmission module 318 can beconfigured to interface to and/or communicate via a wire line cable(e.g., wire line cable 24 of FIG. 1), a telemetry system, or any otherdesired communication system and/or communication media.

In some embodiments, at least some of the components shown in FIG. 5 areincluded within the drill collar implementing LWD 22. For example, atleast some of these components can be placed within one or more cavitieswithin the drill collar. Alternatively, all or some of these componentscan be located within a cartridge that is configured to be coupled to orlocated within the drill collar (e.g., such a cartridge can be suspendedwithin the drilling mud channel). In one embodiment, such a cartridgeincludes components such as electronic circuits, communication circuits,directional sensors (e.g., configured to detect a standard directionalvector, such as the gravity vector or magnetic North), and the like. Insome embodiments, this inner cartridge is retrievable, such that theinner cartridge can be installed and/or withdrawn from LWD tool 22 whileLWD tool 22 is below the surface. For example, the inner cartridge canbe installed or withdrawn through the drillstring using a slick linecable or wireline attached to the upper end of the LWD tool. Thedrillstring can include a muleshoe (not shown) to accept and orient theinner cartridge in such an embodiment.

While certain components are shown as part of the LWD tool in FIG. 5, itis noted that in alternative embodiments, such components can beimplemented within other subs within the drillstring and/or othercomponents within the drilling system. For example, the transmissionmodule 318 and/or directional sensors (not shown) can each beimplemented within another sub. Similarly, all or part of thefunctionality of control module 302 can be implemented within anothersub or within a surface computing device (e.g., a laptop computer). Forexample, in one embodiment, a portion of control module 302 (e.g., theportion that calculates the vector representation of the electromagneticfield detected at each sensor) is implemented in software executing on acomputer system located at the surface. Another portion of the controlmodule 302 (e.g., the portion that controls the operation of oscillator310, switching module 312, analog-to-digital converter 316, andtransmission module 318) can be implemented in hardware, firmware,and/or software residing in LWD 22.

Alternatively, in some embodiments, an LWD tool may store and transmitonly the digitized raw measurements from the sensors, for more detailedcomputations using a computer at a surface location, and thus themajority, or even all, of control module 302 may be implemented at sucha surface computer. In still other embodiments, the LWD tool will bedesigned to process and transmit some of the data as described, but dueto the limited data-rate of transmission available, the complete set ofmeasured data will be stored (e.g., in Flash Memory) within the tool forlater download to a surface computer when the borehole assembly isreturned to the surface (e.g., during a bit run).

While specific equations have been described in the above description ofFIG. 5, it is noted that other embodiments can implement differentequations. For example, a LWD tool having six sensors will use differentequations than those presented above, which are designed for use with aLWD tool having four sensors.

It is noted that all or some of the control module 302 shown in FIG. 5can be implemented in software executing on a computing device (e.g., apersonal computer, server, personal digital assistant, cell phone,laptop, workstation, or the like). In particular, such a computingdevice includes one or more processors (e.g., microprocessors, PLDs(Programmable Logic Devices), or ASICs (Application Specific IntegratedCircuits)) configured to execute program instructions stored in amemory. Such a memory can include various types of RAM (Random AccessMemory), ROM (Read Only Memory), Flash memory, and the like. Thecomputing device can also include one or more interfaces (e.g., such asnetwork interfaces, one or more interfaces to storage devices, and/orone or more interfaces to an input/output (I/O) device such as akeyboard, digital tablet, mouse, monitor, or the like), which can eachbe coupled (e.g., by a bus or other interconnect) to the processor(s)and memory.

It is noted that the program instructions and data (e.g., such as ahistory log and/or lookup table) consumed by and/or implementing all orpart of control module 302 can be stored on various computer readablemedia such as memory 320. In some embodiments, such program instructionscan be stored on a computer readable storage medium such as a CD(Compact Disc), DVD (Digital Versatile Disc), hard disk, optical disk,tape device, floppy disk, and the like. In order to be executed by aprocessor, the instructions and data are loaded into memory from theother computer readable storage medium. The instructions and/or data canalso be transferred to a computing device for storage in memory via anetwork such as the Internet or upon a carrier medium.

FIG. 8A illustrates how a sensor can be placed in the wall of a LWD tool22. The view in FIG. 8A looks at the surface of the drill collar, andthe long axis of the sensor is represented by the dashed arrow. FIG. 8Bshows a cross-sectional view of the drill collar, when viewed indirection A-A marked on FIG. 8A. As shown in these figures, a meanderingchannel 820 has been formed in the drill collar. In addition, across-drilled hole 840 provides a location for a receiver sensor, asshown in cross-section in FIG. 8B, and the combination of the meanderingchannel 820 and the hole 840 operatively breaks the path of continuousmetal around sensor 830. A wiring channel 810 connects this channel toan electrical connector 800, which can provide a voltage induced in areceiver sensor 830 disposed in a transverse hole 840 in the drillcollar to other circuitry (e.g., circuitry 300 of FIG. 5) for furtherprocessing.

Meandering channel 820 and wiring channel 810 can be filled withnon-conducting material, such as a composite epoxy/ceramic material oran elastomer which surrounds and protects a receiver sensor 830 in hole840, and wires (in wiring channel 810) coupling the receiver sensor toelectrical connector 800.

Using a meandering channel (as opposed to a non-meandering channelhaving the maximum width and length of the meandering channel) retainsmore of the metal of the drill collar. By retaining more of the metal inthe drill collar, the drill collar's strength can be relatively lessaffected by the inclusion of the receiver sensor. Additional, theretained metal can provide increased protection to receiver sensor 830from abrasions and impacts that occur during drilling. At the same time,the meandering channel ensures that there is no electrically conductivepath around receiver sensor 830. If present, such an electricallyconductive path could short-circuit receiver sensor 830.

FIGS. 8A and 8B show how a sensor having its long axis perpendicular tothe axis of the drill collar can be protected by a meandering channelmachined into the surface of the drill collar. A similar configuration,rotated 90° with respect to the orientation of the sensor axis shown inFIG. 8A, can be used to protect a sensor having its long axis parallelto the axis of the drill collar.

Although the present invention has been described in connection withseveral embodiments, the invention is not intended to be limited to thespecific forms set forth herein. On the contrary, the present inventionis intended to cover such alternatives, modifications, and equivalentsas can be reasonably included within the scope of the invention asdefined by the appended claims.

1. A method comprising: transmitting a primary magnetic field from oneor more coils placed on a drill collar; receiving a plurality ofelectrical signals, wherein each of the electrical signals is receivedfrom a respective one of a plurality of sensors, wherein the sensors aredistributed around a circumference of a drill collar, wherein an axis ofat least one of the sensors is perpendicular to an axis of the drillcollar, wherein each of the electrical signals indicates a respectivemagnitude of a measurement of a reflected magnetic field, wherein thereflected magnetic field is reflected from an anomalous geologicalformation; and calculating a vector measurement of the reflectedmagnetic field, based upon the electrical signals.
 2. The method ofclaim 1, wherein each of the electrical signals also indicates a phaseof the magnetic field, relative to the primary magnetic field.
 3. Themethod of claim 1, wherein an axis of a second one of the plurality ofsensors is parallel to an axis of a transmitter coil configured toinduce a primary magnetic field.
 4. The method of claim 3, wherein thecalculating comprises: calculating a plurality of ratios, based upon theelectrical signals; and calculating the vector measurement, dependentupon the ratios.
 5. The method of claim 3, further comprising:calculating an electrical characteristic of a homogeneous geologicalformation and the electrical characteristic of the anomalous geologicalformation, based upon a combination of the electrical signals.
 6. Themethod of claim 1, wherein an axis of each of the plurality of sensorsis perpendicular to an axis of a transmitter coil configured to induce aprimary magnetic field.
 7. The method of claim 1, further comprising:receiving a plurality of second electrical signals, wherein each of thesecond electrical signals is received from a respective one of aplurality of second sensors, and wherein the second sensors aredistributed around the circumference of the drill collar at a distancefrom the sensors, and wherein an axis of each of the second sensors isperpendicular to an axis of each of the sensors.
 8. The method of claim7, further comprising: calculating an electrical characteristic of ahomogeneous geological formation based upon the electrical signals; andcalculating the electrical characteristic of the anomalous geologicalformation, based upon the second electrical signals.
 9. The method ofclaim 1, further comprising: accessing information indicative of aresistivity of the anomalous geological formation; and calculating adistance from the drill collar to the anomalous geological formation,based upon the vector measurement and the information.
 10. The method ofclaim 9, wherein the information is calculated based upon a plurality ofsecond electrical signals, and wherein each of the second signals isreceived from a respective one of a plurality of second sensors.
 11. Asystem comprising: a drill collar; one or more coils configured togenerate a primary magnetic field, wherein the one or more coils aredistributed around a circumference of the drill collar; a plurality ofsensors distributed around a circumference of the drill collar, whereinan axis of at least one of the sensors is perpendicular to an axis ofthe drill collar, wherein the plurality of sensors is configured tooutput a plurality of electrical signals, and wherein each of theelectrical signals indicates a respective magnitude of a measurement ofa reflected magnetic field, wherein the reflected magnetic field isreflected from an anomalous geological formation; and a control modulecoupled to receive information identifying the plurality of electricalsignals and to calculate a vector measurement of the reflected magneticfield, based upon the information.
 12. The system of claim 11, whereinthe control module is located within the drilling subassembly.
 13. Thesystem of claim 11, wherein each of the electrical signals alsoindicates a phase of the magnetic field relative to the primary magneticfield.
 14. The system of claim 11, wherein each of the electricalsignals also indicates a magnitude of the reflected magnetic field. 15.The system of claim 11, wherein an axis of a second one of the pluralityof sensors is parallel to an axis of a transmitter coil configured toinduce a primary magnetic field.
 16. The system of claim 15, wherein thecontrol module is configured to: calculate a plurality of ratios, basedupon the electrical signals; and calculate the vector measurement,dependent upon the ratios.
 17. The system of claim 15, wherein thecontrol module is configured to calculate an electrical characteristicof a homogeneous geological formation and the electrical characteristicof the anomalous geological formation, based upon a combination of theelectrical signals.
 18. The system of claim 11, wherein an axis of eachof the plurality of sensors is perpendicular to an axis of a transmittercoil configured to induce a primary magnetic field.
 19. The system ofclaim 11, further comprising: a plurality of second sensors, wherein thesecond sensors are distributed around the circumference of the drillcollar at a distance from the sensors, wherein an axis of each of thesecond sensors is perpendicular to an axis of each of the sensors,wherein the plurality of second sensors are configured to output aplurality of second electrical signals, and wherein the control moduleis configured to: receive information identifying the plurality ofsecond electrical signals, calculate an electrical characteristic of ahomogeneous geological formation based upon the electrical signals, andcalculate the electrical characteristic of the anomalous geologicalformation, based upon the second electrical signals.
 20. The system ofclaim 11, wherein the control module is configured to: accessinformation indicative of a resistivity of the anomalous geologicalformation; and calculate a distance from the drill collar to theanomalous geological formation, based upon the vector measurement andthe information.
 21. The system of claim 19, further comprising: aplurality of second sensors distributed around the circumference of thedrill collar and configured to output a plurality of second electricalsignals, wherein the control module is configured to calculate theinformation indicative of the resistivity, based upon informationidentifying the plurality of second electrical signals.
 22. The systemof claim 19, wherein a metal surface of the drill collar comprises ameandering channel filled with non-conductive material, and wherein themeandering channel overlays the at least one of the sensors.
 23. Asystem comprising: means for generating a plurality of electricalsignals, wherein the means for generating are distributed around acircumference of a drill collar, wherein an axis of at least one of themeans for generating is perpendicular to an axis of the drill collar,and wherein each of the electrical signals indicates a respectivemagnitude of a measurement of a reflected magnetic field, wherein thereflected magnetic field is reflected from an anomalous geologicalformation; and means for calculating a vector measurement of thereflected magnetic field, based upon the electrical signals.
 24. Thesystem of claim 23, wherein each of the electrical signals alsoindicates a phase of the magnetic field relative to a primary magneticfield.
 25. The system of claim 24, wherein the means for calculatingfurther calculate an electrical characteristic of a homogeneousgeological formation and the electrical characteristic of the anomalousgeological formation, based upon a combination of the electricalsignals.
 26. The system of claim 23, further comprising: means forgenerating a second plurality of electrical signals, wherein the meansfor generating the second plurality of electrical signals aredistributed around the circumference of the drill collar at a distancefrom the means for generating the plurality of electrical signals, andwherein the means for calculating further calculates an electricalcharacteristic of a homogeneous geological formation, based upon theelectrical signals, and the electrical characteristic of the anomalousgeological formation, based upon the second electrical signals.
 27. Thesystem of claim 23, wherein the means for calculating comprises: meansfor accessing information indicative of a resistivity of the anomalousgeological formation; and means for calculating a distance from thedrill collar to the anomalous geological formation, based upon thevector measurement and the information.